Generally, oil and gas wells can be divided into two categories: conventional and unconventional. A conventional well involves the drilling of a well into a reservoir with contents under pressure, which causes the well to produce oil or gas through the release of that pressure. An unconventional well involves the drilling of a well into a resource-rich area where the resources are tightly contained in the crystalline structure of the surrounding rock. In order to free the resources, the rock must be fractured. In common terms, this is known as “fracking.” Fracking makes the resource-rich rock permeable; in many cases additional materials, known as proppants, are added to the fractured rock to maintain the rocks' permeability.
Oil and gas wells can be divided between conventional and unconventional, conventional wells target discrete pools of oil and gas that has been separated by gravity migrated some distance from the source and accumulated in a porous and permeable rock. Unconventional wells target regional accumulations of hydrocarbons trapped in place, at or near the source shale, by very low permeability rock.
In both conventional and unconventional wells, completion is defined as the process by which the well is made ready for production. Each completion can involve a varied combination of many different processes and chemical compositions, with each recipe being dependent on the area of production, resource to be produced, and type of well to be used. For each well, completion data can be collected that can be correlated to the specific “recipe” of processes and chemicals used for the completion of that particular well. As unconventional or conventional wells decline in production, they can be recompleted to increase production rates. As with completion, the processes and chemicals used in recompletions can greatly vary.
Traditionally, decline curves are one of the most extensively used forms of data analysis employed to model production rates of oil and gas wells. Historically, the Arps method has been the prevalent tool used to generate oil and gas well reserve forecasts due to its simplicity and low computational cost. Its biggest advantage is the forecasts can be created independent of the size and shape of the reservoir or the actual drive mechanism in the well. However, the fundamental assumption of Arps equations (boundary dominated flow (BDF) regime and unchanged operating conditions and reservoir) are rarely met by unconventional oil and gas wells in ultra-low permeability reservoirs. To overcome the BDF limitation of the Arps model, several new empirical models for decline curve analysis have been developed, including the Multi Segment Arps, Stretched Exponential Production Decline and the Duong models. Moreover, it has been recognized that decline curve analysis was only applicable during the depletion period of the well and thus the early production life of a well is not analyzable by conventional decline curve methods. Since that time, a new set of decline curves that extend the Arps-type curves into the transient flow region has been derived.
In spite of some limitations, the Arps and Duong models both do an acceptable job of fitting a curve to existing production decline; the execution of this task is neither difficult nor controversial. The more important issue is how reliably these models can predict what will happen with production rates when data are noisy (do not follow a clear trend line), have gaps, or are entirely absent.
In the United States, some states report production at the lease level rather than at the well level. A lease can be defined as any contract, profit-sharing arrangement, joint venture, or agreement issued or approved by the U.S. under a mineral leasing law that authorizes exploration for, extraction of, or removal of oil or gas. An older lease can have up to or more than 100 wells on a single lease, the majority of which are producing at differing rates. To compensate, many companies have developed estimated oil/gas production values based on the monthly volume from each well on the lease. Most of the allocation methodologies rely strongly on well test data and pending production files to estimate production of the well.
However, some states do not require regular testing, while others require reports either on annual or semi-annual basis. This results in recently completed wells only having, at most, a single measured data point, meaning that the more recent a well has been completed, the higher the uncertainty in the allocated production measurement. Indeed, in some states, the average time before a production measurement is taken can be upwards of 400 days after the well has been completed. For lease owners and operators, as well as for those third-party suppliers that provide supplies and services to the owners and operators, a more accurate system is needed to estimate allocated production, in order for those parties to better allocate resources and more economically administrate their holdings and customers.